Wellbores are formed in subterranean formations for various purposes including, for example, the extraction of oil and gas from a subterranean formation and the extraction of geothermal heat from a subterranean formation. A wellbore may be formed in a subterranean formation using a drill bit, such as, for example, an earth-boring rotary drill bit. Different types of earth-boring rotary drill bits are known in the art, including, for example, fixed-cutter bits (which are often referred to in the art as “drag” bits), rolling-cutter bits (which are often referred to in the art as “rock” bits), diamond-impregnated bits, and hybrid bits (which may include, for example, both fixed cutters and rolling cutters). Earth-boring rotary drill bits are rotated and advanced into a subterranean formation. As the drill bit rotates, the cutters or abrasive structures thereof cut, crush, shear, and/or abrade away the formation material to form the wellbore. A diameter of the wellbore drilled by the drill bit may be defined by the cutting structures disposed at the largest outer diameter of the drill bit.
The drill bit is coupled, either directly or indirectly, to an end of what is referred to in the art as a “drill string,” which comprises a series of elongated tubular segments connected end-to-end that extends into the wellbore from the surface of the formation. Often various tools and components (often referred to in the art as “subs”), including the drill bit, may be coupled together at the distal end of the drill string at the bottom of the wellbore being drilled. This assembly of tools and components is referred to in the art as a “bottom-hole assembly” (BHA).
The drill bit may be rotated within the wellbore by rotating the drill string from the surface of the formation, or the drill bit may be rotated by coupling the drill bit to a downhole motor, which is also coupled to the drill string and disposed proximate the bottom of the wellbore. The downhole motor may comprise, for example, a hydraulic Moineau-type motor having a shaft, to which the drill bit is mounted, that may be caused to rotate by pumping fluid (e.g., drilling mud or fluid) from the surface of the formation down through the center of the drill string, through the hydraulic motor, out from nozzles in the drill bit, and back up to the surface of the formation through an annular space between the outer surface of the drill string and the exposed surface of the formation within the wellbore.
It is known in the art to use what is referred to in the art as a “reamer” (also referred to in the art as a “hole opening device” or a “hole opener”) in conjunction with a drill bit as part of a BHA when drilling a wellbore in a subterranean formation. In such a configuration, the drill bit operates as a “pilot” bit to form a pilot bore in the subterranean formation. As the drill bit and BHA advance into the formation, the reamer follows the drill bit through the pilot bore and enlarges the diameter of, or “reams,” the pilot bore.
Conventionally in drilling oil, gas, and geothermal wells, casing is installed and cemented to prevent the wellbore walls from caving into the subterranean borehole while providing requisite shoring for subsequent drilling operations to achieve greater depths. To increase the depth of a previously drilled borehole, Previously Presented casing is laid within and extended below the previous casing. While adding casing allows a borehole to reach greater depths, it has the disadvantage of narrowing the borehole. Narrowing the borehole restricts the diameter of any subsequent sections of the well because the drill bit and any further casing must pass through the existing casing. As reductions in the borehole diameter limit the production flow rate of oil and gas through the borehole, it is often desirable to enlarge a subterranean borehole to provide a larger borehole diameter beyond previously installed casing.
Expandable reamers may include reamer blades pivotably or hingedly affixed to a tubular body and actuated by way of a piston disposed therein as disclosed by U.S. Pat. No. 5,402,856 to Warren. In addition, U.S. Pat. No. 6,360,831 to Åkesson et al. discloses a borehole opener comprising a body equipped with at least two hole opening arms having cutting means that may be moved from a position of rest in the body to an active position by exposure to pressure of the drilling fluid flowing through the body. The blades in these reamers are initially retracted to permit the tool to run through the borehole on a drill string and, once the tool has passed beyond the end of the casing, the blades are extended so the bore diameter may be increased below the casing.
Expandable reamers include activation means for moving the reamer blades thereof between a deactivated position and an expanded, activated position. For example, prior known expandable reamers include a movable sleeve coupled to the reamer blades. As the movable sleeve moves axially within a body of the expandable reamer, the reamer blades move between the deactivated position and the activated position. The movement of the movable sleeve is accomplished by causing a pressure differential to push the movable sleeve in the desired axial direction. The pressure differential is provided by dropping a so-called “drop ball” into the drilling fluid. An orifice in the drilling fluid flow path smaller than the drop ball is provided in the expandable reamer, such that the drop ball cannot pass the orifice. When the drop ball reaches the orifice, pressure from the drilling fluid builds up above the drop ball, pushing the drop ball downward along with the structure in which the orifice is formed. Drilling fluid may then be directed to provide pressure against the movable sleeve, moving the movable sleeve upward and, consequently, moving the blades into the activated position. When drilling fluid pressure is released from against the movable sleeve, a spring biases the movable sleeve to move back into the deactivated position.